Two-stage downhole oil-water separation

ABSTRACT

A method for downhole oil-water separation, according to one or more aspects of the present disclosure, comprises disposing a oil-water separation system in a wellbore, the system comprising a first separator connected in hydraulic series with a second separator; separating a well fluid in the first separator into a first injection stream and a first production stream; discharging the first injection stream to an inlet of the second separator; separating the first injection stream in the second separator into an output injection stream and a second production stream; and injecting the output injection stream from the wellbore into an injection formation.

BACKGROUND

This section provides background information to facilitate a better understanding of the various aspects of the present invention. It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art.

Oil well production can involve pumping a well fluid that is part oil and part water, i.e., an oil-water mixture. As an oil well becomes depleted of oil, a greater percentage of water is present and subsequently produced to the surface. The “produced” water often accounts for at least 80 to 90 percent of a total produced well fluid volume, thereby creating significant operational issues. For example, the produced water may require treatment and/or re-injection into a subterranean reservoir in order to dispose of the water and to help maintain reservoir pressure. Also, treating and disposing produced water can become quite costly.

One way to address those issues is through employment of a downhole device to separate oil-water and re-inject the separated water, thereby minimizing production of unwanted water to surface. Reducing water produced to surface can allow reduction of required pump power, reduction of hydraulic losses, and simplification of surface equipment. Further, many of the costs associated with water treatment are reduced or eliminated.

However, successfully separating oil-water downhole and re-injecting the water is a relatively involved and sensitive process with many variables and factors that affect the efficiency and feasibility of such an operation. For example, the oil-water ratio can vary from well to well and can change significantly over the life of the well. Further, over time the required injection pressure for the separated water can tend to increase.

SUMMARY

A downhole fluid separation system according to one or more aspects of the present disclosure comprises a first oil-water separator comprising an inlet, a first water outlet and a first oil outlet; and a second oil-water separator comprising an inlet, a second water outlet and a second oil outlet, wherein the inlet of the second oil-water separator is connected in hydraulic series to the first water outlet.

The first oil-water separator may comprise one selected from the group of a static separator and a dynamic separator; and the second oil-water separator may comprise one selected from the group of a static separator and a dynamic separator. In at least one embodiment the first oil-water separator and the second oil-water separator are of the same type of separator.

According to one or more aspects of the present disclosure a system comprises a wellbore in communication with a production zone and an injection zone; a pump positioned in the wellbore having an inlet in fluid communication with a well fluid; a first separator having an inlet, a first water outlet and a first oil outlet, the inlet in fluid connection with a pump discharge; and a second separator having an inlet, a second water outlet and a second oil outlet, the inlet of the second separator connected in hydraulic series to the first water outlet and the second water outlet in fluid communication with the injection zone.

A method for downhole oil-water separation, according to one or more aspects of the present disclosure, comprises disposing an oil-water separation system in a wellbore, the system comprising a first separator connected in hydraulic series with a second separator; separating a well fluid in the first separator into a first injection stream and a first production stream; discharging the first injection stream to an inlet of the second separator; separating the first injection stream in the second separator into an output injection stream and a second production stream; and injecting the output injection stream from the wellbore into an injection formation.

The foregoing has outlined some of the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter which form the subject of the claims of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 is a schematic diagram of a downhole oil-water separation system, according to one or more aspects of the present disclosure

FIG. 2 is a schematic of an embodiment of a downhole oil-water separation system according to one or more aspects of the present disclosure disposed in a well having an injection zone positioned below the production zone.

FIG. 3 is a schematic of another embodiment of a downhole oil-water separation system according to one or more aspects of the present disclosure disposed in a well having an injection zone positioned below the production zone.

FIG. 4 is a schematic of an embodiment of a downhole oil-water separation system according to one or more aspects of the present disclosure disposed in a well having the production zone positioned below the injection zone.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.

As used herein, the terms “up” and “down”; “upper” and “lower”; “top” and “bottom”; and other like terms indicating relative positions to a given point or element are utilized to more clearly describe some elements. Commonly, these terms relate to a reference point as the surface from which drilling operations are initiated as being the top point and the total depth of the well being the lowest point, wherein the well (e.g., wellbore, borehole) is vertical, horizontal or slanted relative to the surface.

In this disclosure, “hydraulically coupled” or “hydraulically connected” and similar terms (e.g., pneumatic, fluidic), may be used to describe bodies that are connected in such a way that fluid pressure may be transmitted between and among the connected items. The term “in fluid communication” is used to describe bodies that are connected in such a way that fluid can flow between and among the connected items. It is noted that hydraulically coupled may include certain arrangements where fluid may not flow between the items, but the fluid pressure may nonetheless be transmitted. Thus, fluid communication is a subset of hydraulically coupled.

The present disclosure is directed to downhole oil-water separation (e.g., processing) systems. According one or more aspects of the present disclosure, downhole oil-water separation systems are provided for wells having a water cut of 50 percent or greater. According to one or more aspects of the present disclosure, downhole oil-water separation systems are provided for water cuts of about 80 percent and greater. According to one or more aspects of the present disclosure, downhole oil-water separation systems are provided to reduce the oil content in the injection string below 100 ppm in wells having a water cut of about 80 percent or greater.

Downhole oil-water separation generally comprises static separation, utilizing one or more hydrocyclone liners, and dynamic separation which utilizes a centrifuge separator rotating at the same operating speed of an electrical submersible pump (“ESP”). Hydrocyclone liners are available in different diameters. Small diameter liners, known as deoilers, have quality separation performance but are flow rate limited. To overcome the flow rate limitations of deoilers, multiple deoilers can be operated in hydraulic parallel. For example, in surface operations several hundred deoilers (e.g., 1 inch (2.54 cm) diameter) each passing a few hundred barrels (“bbl”) per day (“bpd”) may be utilized in hydraulic parallel to handle the required flow rate. This approach is impractical in downhole applications. Thus, larger deoilers (e.g., 3 inch diameter) are often used to boost flow rate capabilities at the expense of separation performance. Examples of some present and prior high quality downhole oil-water separation systems are disclosed in U.S. Pat. No. 5,961,841 and U.S. Patent Application Publication Nos. 2009/0242197 and 2009/0056939 which are incorporated herein by reference.

FIG. 1 is a schematic diagram of a downhole oil-water separation system, generally denoted by the numeral 10, according to one or more aspects of the present disclosure. Depicted system 10 may be generally described as a two-stage separation system, wherein the first stage separator and the second stage separator are connected in hydraulic series.

System 10 comprises a first stage separator 12 (e.g., bulk) and a second stage separator 14 connected in hydraulic series. The total inlet fluid 16 (e.g., wellbore fluid, formation fluid) is drawn (e.g., injected) into first stage injector 12 through inlet 12 a wherein total inlet fluid stream 16 is separated into a first injection stream 17 comprising the higher water portion stream of total inlet stream 16 and a first production stream 18 comprising the higher hydrocarbon (e.g., oil) portion. First production stream 18 is discharged from an outlet 18 a (e.g., oil outlet, production outlet) and may be directed to the surface as the production outlet stream 20. First injection stream 17 is discharged from an outlet 17 a (e.g., water outlet, injection outlet) becomes the inlet stream (via inlet 14 a) to second stage separator 14. First injection stream 17 is separated into the injection stream 19 and a second production stream 22. Injection stream 19 is discharged from an outlet 19 a and is injected into an injection zone of the geological formation surrounding the well, provided it satisfies the required stream quality. Second production stream 22 is discharged through an outlet 22 a and may be produced to the surface or discharged to the wellbore. In FIG. 1, second production stream 22 is depicted produced to the surface as production outlet stream 20.

First production stream 18 may bypass second stage separator 14 and be produced directed to the surface (e.g., production stream 20) or it may be combined with second production stream 22 for lifting to the surface. Due to the additional pressure drop from second stage separator 14, second stage production stream 22 will have a lower pressure than that of first production stream 18. Before production streams 18, 22 can be combined, the pressures must be balanced, for example via device 24. Device 24 may comprise an apparatus for reducing the pressure of first production stream 18 and/or to increase the pressure of second production stream 22. For example, device 24 may comprise a pump for boosting the pressure of second production stream 22.

An example of a pressure balancing device 24 that reduces the pressure of first production stream 18 may be integrated for example in first stage separator 12 or second stage separator 14 or provided in a separate module. Pressure reduction balancing device 24 may comprise for example a valve (e.g., fixed or adjustable) to provide the pressure drop. Device 24 may further comprise a check valve and/or one or more sensors (e.g., gauges) such as, and without limitation, flow rate sensors, pressure sensors, and oil-water concentration gauges.

According to one or more aspects to the present disclosure, system 10 may be particularly adapted for use in a well having a water cut of about 50 to 80 percent and needing a low oil-content injection stream, for example lower than 500 ppm of oil (e.g., water cut of about 99.95% or lower).

First stage separator 12 and second stage separator 14 may be of the same type of separator (e.g., static, hydrocyclone) or different types of separators. It is noted that first and or second stage separator 12, 14 may comprise more than one separator. For example, a stage separator may comprise cascades of hydrocyclone liners arranged in hydraulic parallel.

An example of a system 10, according to one or more aspects of the present disclosure, for providing an injection stream to a range of about 100 ppm from a high water-cut (e.g., greater than about 80 percent water) total inlet stream 16 is now described with reference to FIG. 1. First stage separator 12 separates total inlet fluid stream 16 into a first injection stream 17 having an oil-in-water concentration of about 500 ppm. First injection stream 17 is introduced in hydraulic series to second separator stage 14. Second stage separator 14 separates first injection stream 17 into an outlet injection stream 19 having an oil-in-water concentration in the range of 100 ppm. In this example, second stage separator 14 may comprise one or more hydrocyclone separators.

An example of a downhole oil-water separation system 10 for use in a low water cut (e.g., about 50 to 80 percent water) is now described with reference to FIG. 1. Total inlet stream 16 (e.g., wellbore fluid) comprises a water cut in the range of about 50 to 80 percent water. Inlet stream 16 is taken into first stage separator 12 (e.g., bulk hydrocyclone liners) wherein a first injection stream 17 having a water cut, for example, of about 99 percent (e.g., 1 percent oil-in-water concentration or 10,000 ppm oil-in water) is provided. First injection stream 17 is passed through second stage separator 14 (e.g., a single static separator) which provides a injection outlet stream 19 comprising an oil-in-water concentration reduced from about 10,000 ppm (e.g., 1 percent) down to approximately 500 ppm of oil-in-water concentration (e.g., 0.05 percent).

FIG. 2 is a schematic of a downhole oil-water separation system 10 according to one or more aspects of the present disclosure disposed in a well 26. System 10 is disposed downhole in wellbore 28 of well 26. In this embodiment, the production zone 30 is located above the injection zone 32 relative to surface 34 of well 26. Total inlet stream 16 is formation fluid that is produced from production zone 30 into wellbore 28. Injection stream 19 is injected into injection zone 32.

Depicted system 10 comprises first stage separator 12 connected in hydraulic series with second stage separator 14 and a downhole pump 36. Downhole pump 36 is depicted as an electrical submersible pump comprising a motor 38. Total inlet fluid 16 is drawn into inlet 40 of pump 36, thus into the separation process flow path, and discharged from pump outlet 36 a into inlet 12 a of first stage separator 12. Total inlet fluid 16 is separated in first stage separator 12 into a first injection stream 17 and a first production stream 18. First injection stream 17 and first production stream 18 pass through a flow control manifold 42 wherein first injection stream 17 is directed through a conduit 44 (e.g., bypass conduit) to second stage separator 14. In this embodiment, first production stream 18 is produced to the surface 34 as output production stream 20 through tubing 46.

In second stage separator 14, depicted as a deoiler in FIG. 2, first injection stream 17 is separated into an output injection stream 19 and a second production stream 22. In this embodiment, the oil portion (e.g., second production stream 22) is discharged from second stage separator 14 into the annulus 48 of wellbore 28 above packer 50. Packer 50 isolates injection zone 32 from production zone 30 and inlet 40 of the oil-water separation process path. Annulus 48 is defined between the wellbore wall 52 (e.g., casing) and the exterior of conduit 44. Injection stream 19, discharged from second stage separator 14, flow through the bore of conduit 44 across packer 50 where it is injected into formation zone 32.

Depicted system 10 comprises a sensor system 54 (e.g., package, module). In the embodiment depicted in FIG. 2, sensor system 54 is disposed down stream of second stage separator 14 and upstream of injection zone 32 in hydraulic communication with injection stream 19. Sensor system 54 may be utilized for monitoring a variety of characteristics related to the downhole fluid processing, including pressure, temperature, chemistry, vibration, fluid composition, and other characteristics. Examples of sensors that can be incorporated into sensor system 54 include oil-in-water sensors, sand-in-water sensors, flow meters, pressure sensors, chemistry sensors, and vibration sensors that enable the system operation to be optimized. In some applications, sensor system 54 may enable real-time corrections based on data provided by the sensor system to reduce the risk of system failure or damage.

For a variety of reasons, including local regulations, it may be desirable to limit oil-in-water levels for certain applications. The sensor system enables monitoring to ensure the separated water (e.g., outlet injection stream 19) does not exceed the desired/required level of oil in the water component. The sensor system can be designed to provide an alarm or other indication to an operator to enable adjustment to the downhole fluid processing parameters. For example, adjustments can be made to the backpressure at the stage separators via the flow-restrictor, or adjustments can be made to other components to regulate well head pressure, to adjust speed of an electric submersible pump, or to make other adjustments. Furthermore, monitoring of the oil-in-water content of outlet injection stream 19 can be useful in limiting potentially harmful impacts on the injection zone. The sensor system provides operators with advance notice to enable the taking of corrective action, such as scheduling a stimulation procedure before the injection zone becomes severely plugged.

FIG. 3 is a schematic diagram of another embodiment of a downhole oil-water separation system 10 according to one or more aspects of the present disclosure. In the depicted embodiment, injection zone 32 is disposed below production zone 30 relative to surface 34. System 20 comprises a packer 50 isolating production zone 30 from injection zone 32. Formation fluid 16 enters wellbore 28 at production zone 30 and enters the downhole oil-water system 10 at inlet 40 of pump 36 from which it is pumped into first stage (e.g., bulk) separator 12. First stage separator 12 separates a first production stream 18 (e.g., oil stream) and a first injection stream 17 (e.g., water stream) which pass into flow manifold 42 via a dual conduits 56 for example. First production stream 18 is routed at flow manifold 42 to the surface through conduit 46 as output production stream 20. Flow manifold 42 routes first injection stream 17 into second stage separator 14 (e.g., deoiler) which separates first injection stream 17 into an output injection stream 19 and a second production stream (e.g., oil stream). The oil stream from second stage separator 14 is directed uphole to surface 34 via tubular 46 as output production stream 20. The output injection stream 19 continues downhole in the depicted embodiment through conduit 44 through packer 50 where it is injected into injection formation 32.

FIG. 4 is a schematic of a downhole oil-water separation system 10 according to one or more aspects of the present disclosure disposed in a well wherein production zone 30 is located below injection zone 32. In this embodiment inlet 40 is disposed in an internal chamber 57 (e.g., bore) of a housing 58. In the depicted embodiment, pump 36 and first stage separator 12 are also disposed inside of housing 58. Chamber 57 of housing 58 is in fluid communication with production zone 30 through packer 50. Injection zone 32 is isolated from inlet 40 via housing 58 and isolated from production zone 30 via packer 50.

Production fluid 16 enters wellbore 28 and passes into housing 58 where it enters the downhole separation process flow path at inlet 40 of pump 36 in this embodiment. First stage separator 12 separates total inlet stream 16 into a first injection stream 17 and a first production stream 18. The water and oil stream may be passed from first stage separator 12 through dual conduit 56 for example to a flow manifold 60. First production stream 18 is routed to surface 34 via tubular 46. First injection stream 17 is directed to second stage separator 14 where it is separated into output injection stream 19 and second production stream 22 (see FIG. 1). The second production stream (e.g., oil stream) off of second stage separator 14 is pumped to the surface via flow manifold 42 and tubular 46 for example. Second injection stream 19 is routed through flow manifold 42, in the depicted embodiment, and discharged into wellbore 28 (e.g., casing 52) and injected into zone 32 of the formation.

The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the present disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure. The scope of the invention should be determined only by the language of the claims that follow. The term “comprising” within the claims is intended to mean “including at least” such that the recited listing of elements in a claim are an open group. The terms “a,” “an” and other singular terms are intended to include the plural forms thereof unless specifically excluded. 

1. A downhole fluid separation system comprising: a first oil-water separator comprising an inlet, a first water outlet and a first oil outlet; and a second oil-water separator comprising an inlet, a second water outlet and a second oil outlet, wherein the inlet of the second oil-water separator is connected in hydraulic series to the first water outlet.
 2. The system of claim 1, wherein the first oil-water separator comprises a static separator.
 3. The system of claim 1, wherein the second oil-water separator comprises a static separator.
 4. The system of claim 1, wherein: the first oil-water separator comprises one selected from the group of a static separator and a dynamic separator; and the second oil-water separator comprises one selected from the group of a static separator and a dynamic separator.
 5. The system of claim 4, wherein the first oil-water separator and the second oil-water separator are of the same type of separator.
 6. The system of claim 1, further comprising a downhole pump having a discharge in fluid communication with the inlet of the first oil-water separator.
 7. The system of claim 6, wherein: the first oil-water separator comprises one selected from the group of a static separator and a dynamic separator; and the second oil-water separator comprises one selected from the group of a static separator and a dynamic separator.
 8. The system of claim 7, wherein the first oil-water separator and the second oil-water separator are of the same type of separator.
 9. A system comprising: a wellbore in communication with a production zone and an injection zone; a pump positioned in the wellbore having an inlet in fluid communication with a well fluid; a first separator having an inlet, a first water outlet and a first oil outlet, the inlet in fluid connection with a pump discharge; and a second separator having an inlet, a second water outlet and a second oil outlet, the inlet of the second separator connected in hydraulic series to the first water outlet and the second water outlet in fluid communication with the injection zone.
 10. The system of claim 9, wherein: the first oil-water separator comprises one selected from the group of a static separator and a dynamic separator; and the second oil-water separator comprises one selected from the group of a static separator and a dynamic separator.
 11. The system of claim 10, wherein the first oil-water separator and the second oil-water separator are of the same type of separator.
 12. The system of claim 9, wherein: the production zone is located above the injection zone; and. the first separator is positioned above the second separator.
 13. The system of claim 9, wherein: the production zone is located above the injection zone; and. the second separator is positioned above the first separator.
 14. A method for downhole oil-water separation, comprising: disposing a oil-water separation system in a wellbore, the system comprising a first separator connected in hydraulic series with a second separator; separating a well fluid in the first separator into a first injection stream and a first production stream; discharging the first injection stream to an inlet of the second separator; separating the first injection stream in the second separator into an output injection stream and a second production stream; and injecting the output injection stream from the wellbore into an injection formation.
 15. The method of claim 14, wherein the well fluid comprises a water cut in the range of about 80 percent water or greater.
 16. The method of claim 15, wherein the output injection stream comprises an oil content in the range of 100 parts per million or less.
 17. The method of claim 14, further comprising: directing the first production stream to the surface; and directing the second production stream into the wellbore.
 18. The method of claim 14, comprising: directing the first production stream to the surface; and directing the second production stream to the surface.
 19. The method of claim 14, wherein the well fluid comprises a water cut in the range of about 50 percent to 80 percent water.
 20. The method of claim 19, wherein the output injection stream comprises an oil content of about 500 parts per million or less. 